In 4D imaging, gathering and analyzing information in order to monitor the changing geometry of the oil/water, oil/gas or gas/water boundary in a reservoir is a time consuming and expensive process. In prior art practice, seismic information is gathered periodically by activating or firing sources and sensing the reflections. The data are processed and a calculated result determines reflectivity changes over time as water replaces oil in a reservoir. Such seismic information is gathered in land and marine environments. On land the arrays of source and receivers are moved after each seismic data taking, whereas in marine environments the arrays of sources and receivers are towed behind boats in overlapping patterns.
Specialized companies perform such services and the demand for these services makes scheduling difficult. The services are expensive and dangerous when operating around existing oil platforms and other shipping as the arrays may be up to 3 kilometers long.
Monitoring of the oil geometry is important since the productivity of the reservoir may be in jeopardy, and early knowledge may be critical so that action may be taken to stem the loss of production or otherwise manage and plan for future production rates. In FIG. 1, item 1 is a rudimentary characterization of an earlier outline of the oil geometry of a known reservoir. Oil producing wells are shown 3. However, at a later time the dotted line 5 shows the oil geometry where well 3' is non-producing and 3" is isolated from the rest of the oil. Such information is needed for proper planning and action regarding this oil reservoir. There are known techniques that may be used to boost production of the oil producing wells that experience production losses. For example, side wells may be drilled, forcing water or steam or modulating flow rates are some known techniques.
With regard to oil reservoirs beneath the sea, navigation is recorded and is crucial to proper surveying since the location must be known and repeatable. The resolution of such prior art surveying is likely no better than 6% from survey to survey. Ships constantly troll with several hundred hydrophones trailing behind in multiple streamers. An energy source (usually an air gun array), often closest to the ship, is positioned along one of more of the streamers and fired at 5 to 10 second intervals. The reflected seismic waves or signals are received by hydrophone streamers that, as stated above, may be as long as 3 kilometers. Several hundred hydrophones may receive the signals after each firing. The signals are digitized and recorded on magnetic tape. After acquisition, the data is processed and interpreted by large computers. This processing comprises: 1) deconvolution, 2) stacking, and 3) migration. Each of these steps may be further analyzed into sub-steps. U.S. Pat. No. 5,349,527 ('527), issued on Sep. 9, 1994, assigned to Schlumberger Technology Corp., suggests that the costs of taking and processing the data run into millions of dollars and take weeks of processing time on very large computers. The time and cost is a limitation on the use of such procedures.
An inherent problem of the prior art techniques that make the data reduction difficult is that source signals may take many paths to the sensors, and since the sources produce energy along widely dispersed directions there are multiple reflections and refractions which may be received by the sensors. Furthermore, the geometric and velocity structure of the reservoir's overburden are not known.
In view of the above difficulties, techniques have been developed to migrate the data to place the reflection event at the appropriate physical location in the subsurface. These techniques and others are detailed in an article printed in RESERVOIR GEOPHYSICS, authored by Robert E. Sheriff, in 1992. This article is hereby incorporated herein by reference as though laid out in full. However, implementation of these techniques, as noted above, requires large amounts of data just to position the reflection points. FIG. 2 illustrates the use of one such technique, called the Kirchoff's method of migration. The half ellipse 4 is the set of points that will give rise to a set of reflections all sharing the same travel time, assuming a uniform velocity field and a source and receiver at each focus of the ellipse. It is noted that this method can be extended, as known in the art, to heterogeneous velocity fields and multiple true reflections. With the source 2 at one focus and the receiver 6 is at the other focus, the specular seismic ray of interest, the true reflection from the surface 10 is shown in the solid line 8. In this example, there is a true reflection 8, but the location of the surface 10 is not known since other reflections anywhere on the ellipse 4, say ray 9 as reflected from point 7, have the same travel time. In this specific example assume that there is only one reflective surface 10, at the bottom of the ellipse 4. However, the technique as known in the art is applicable to true reflective surfaces at other locations along the ellipse 4. If the source and receiver are moved to locations 2' and 6', respectively, and the source is fired the reflection from the surface 10 defines ellipse 4'. Ray 8' will have the same travel time for ellipse 4' as did ray 8 in ellipse 4. But, the travel time from location 7 on the ellipse 4 will be different when the source is at location 2'. Any reflection from point 7 will define a larger ellipse and the accompanying longer time of travel. But since there is no reflective surface at point 7 (in this example) there will be no reflection signal received that corresponds to that larger ellipse. By repeatedly (say forty to fifty times) moving the source/receiver and firing the source, new ellipses are formed and by superimposing many such ellipses calculated from the many firings, the specular ray of interest reflected from surface 10 will be reinforced in each ellipse thereby determining the actual location of the reflective surface 10. The possible alternative points along the first ellipse will destructively reinforce (since there are no reflective surfaces in this example).
In partial summary, the above processes have the following limitations: a) large amounts of data must be taken, b) processing of the data is time consuming and expensive, c) specialized companies perform these services and the acquiring and scheduling of these services may be difficult, and d) data collecting may impede or be impeded by production operations.
It is an object of the present invention to use the prior knowledge of the geometric and velocity structure of the reservoir's overburden obtained from previous 2D and 3D seismic surveys to minimize the subsequent data acquisition and processing to perform 4D reservoir imaging.
Another object of the present invention is to reduce the scheduling problems and logistics of 4D imaging, and to provide a less time consuming process of collecting 4D imaging data.
It is another object of the present invention to maintain sensitivity of .+-.1% over the frequency bands of interest herein.
It is yet another object of the present invention to detect the changing geometry of a 4% impedance discontinuity with at least 4% positioning resolution.
It is another object of the present invention to lower data acquisition time and the need for large computers by utilizing data from prior surveys.
It is an object to use fewer sensors by locating source firings or operations such that single receivers may receive specular reflections from more than one area or patch on the oil reservoir.
It is another object to collect a minimum amount of seismic data while providing higher resolution than with prior art apparatus and techniques.
Yet another object to pre-calculate positions of sources and sensors from known data and to determine therefrom a time window in which to gather data.